Because of the high value of condensate and liquids, oil and gas fields are often injected with nitrogen to increase oil and gas production. As a consequence, the nitrogen content in the feed gas to a downstream gas processing plant from such fields will increase over time. For example, in the initial phase of the gas processing plant operation, nitrogen content in the feed gas from the field is typically low (e.g., 1-3 mol %). As enhanced oil recovery process continues, the nitrogen content in the feed gas to the gas plant can significantly increase (e.g., to as high as 18-30 mol %), which in most cases necessitates the use of a nitrogen rejection unit to remove the nitrogen from processed gas to meet pipeline transmission specification (e.g., typically 3 mol %).
In addition to nitrogen removal, CO2 is also present in most feed gas streams from a gas well and must be removed by an acid gas removal unit (e.g., to 1-2 mol %) to avoid CO2 freezing in a downstream demethanizer column in which natural gas liquids are recovered from the feed gas. CO2 removal is typically performed using an amine unit and produces in most cases a feed stream to a downstream natural gas recovery unit (NGL recovery unit) that will have sufficiently low CO2 content to avoid freezing issues in the NGL recovery unit (e.g., operating at about −150° F. to remove C2+ components). However, a typical NRU operates at a much lower temperatures (e.g., as low as −250° F.), and at such low cryogenic temperatures, the NRU feed gas must contain no more than 0.001 to 0.002 mol % (200 to 2000 ppmv) CO2. Unfortunately, such low levels are commonly not achievable with the amine units of most existing gas processing plants as these units are designed for production of a feed gas to an NGL recovery unit, but not for deep CO2 removal. Thus, in many cases an acid gas removal unit must be revamped for deep CO2 to meet the NRU feed gas specification as exemplarily depicted in Prior Art FIG. 1, described in more detail below.
An amine unit revamp option typically requires increasing solvent circulation and heating duties, and changing out the existing solvent with a more aggressive amine solvent such as DGA (Diglycolamine) or activated MDEA (Methyl Diethanolamine). While such option is at least conceptually possible, capital requirements and operating costs are often very high and require extended plant shutdown, which is generally not desirable. Moreover, most amine plants already operate at maximum capacity and do not have room for further solvent increase. Alternatively, a new amine unit can be added downstream of the NGL recovery unit as exemplarily depicted in Prior Art FIG. 2, and described in more detail below. While additional units are less intrusive than a revamp option, new amine units typically produce a wet treated gas that must be further dried with molecular sieve or other dryers to avoid freezing in the NRU, making this option even more costly.
Nitrogen rejection, CO2 removal, and NGL recovery can be performed in an integrated process having multiple process streams and as fractionation steps as is described, for example, in GB 2500830 or WO 2012/177405. These and all other referenced extrinsic materials are incorporated herein by reference in their entirety. Where a definition or use of a term in a reference that is incorporated by reference is inconsistent or contrary to the definition of that term provided herein, the definition of that term provided herein is deemed to be controlling. In another approach, CO2 freezing can be entirely avoided by use of a solvent process as described in U.S. Pat. No. 5,406,802 or US 2002/0139244. While such known systems and methods are generally effective for their intended purpose, they will require in most cases de novo installations and will not be suitable for revamps.
Thus, although various configurations and methods are known to reject nitrogen from the feed gas, all or almost all suffer from one or more disadvantages. Among other things, feed gas to the NRU from an upstream CO2 removal unit will often have a CO2 content that is unsuitable for feeding into an NRU, or to achieve low CO2 levels, existing amine units have to be modified or additional amine units must be installed. Viewed from a different perspective, sufficient CO2 removal by an existing amine (or other CO2 removal) unit is not provided or too expensive for economic implementation into a plant with the existing amine (or other CO2 removal) unit. Moreover, where additional amine units are provided, the treated gas is frequently too wet for direct feeding into the NRU and must be dried. Thus, there is still a need to provide improved methods and configurations for CO2 removal in high nitrogen feed gases.